Wells with extended (and possibly multiple) reservoir contact or “reach” are becoming more commonly deployed for more efficient production of oil and gas from fragmented reservoirs. Extended reach wells are typically segmented into multiple zones or branches (or laterals). Typically, fluid streams produced by individual branches or zones of a well are commingled into multiphase streams sub-surface within the well. In the current state of the art, the individual subsurface zones and branches are equipped with downhole pressure gauges, zonal isolation packers and inflow control devices, which allow the control of fluids from the different parts of the reservoir or different reservoirs into the individual zones or branches. The well fluids then flow to the surface where they are routed to one or more production manifold (header) conduits and further commingled with production from other wells. The commingled fluids are then routed via a fluid separation assembly (comprising one or more bulk separators and/or production separators) into fluid outlet conduits for transportation and sales of at least nominally separated streams of oil, water, gas and/or other fluids.
The concept of equipping extended reach wells with downhole pressure gauges, zonal isolation packers and inflow control devices, and other additional downhole sensing and control equipment, which will be referred to as “Smart Wells” below, has been discussed in a large number of patents and other publications, for example International Patent WO 92/08875 (Framo Developments (UK) Ltd. assignee) dated 1992, and U.S. Pat. No. 6,112,817 (Baker Hughes Inc. assignee) dated 2000, and the SPE Papers SPE103222 (McCraken et al), SPE90149 (Brouwer et al), SPE100880 (Obendrauf et al), SPE79031 (Yeten et al.), SPE102743 (Sun et al.), and so on, all of which were published in 2006 or earlier.
Some of the above publications deal mainly with the hardware and a extensive and extensive set of completion equipment, for example International Patent application WO 92/08875, which includes downhole completion sensors for logging and reporting not just pressures and temperatures but also flowrates and compositions. It is the current state of the art that downhole devices which even approximately report flowrates and compositions are widely regarded to be complex, impractical, unreliable and very likely to fail prematurely under the subsurface conditions. Specifically, the practical operational challenge of managing the production of the wells using downhole pressure and temperature production data only are not addressed in the WO 92/08875 prior art reference.
Other publications focus on the methods for operating a Smart Well to obtain maximum benefit, for example U.S. Pat. No. 6,112,817 and the SPE papers cited. All of these make broad assumptions on the operability of the wells, in particular that production rates and phases from each zone are available. This assumption is not practical and the operational challenge of tracking the production of the wells using downhole pressure and temperature production data only is not addressed. For example, U.S. Pat. No. 6,112,817 assumes that the flowrates and phases (oil, water, gas) from each of the zones is known or can be calculated from the sensors and other devices located downhole (Column 4, line 27, 67, Column 5, lines 1, 43 Column 6, line 26). U.S. Pat. No. 6,112,817 also assumes some mechanism for updating the underlying reservoir models (Column 2, line 49, Column 5, line 2) as a pre-requisite for computing the required control strategy. However, no specific downhole multiphase flow measurement device or algorithm is suggested for the practical computation of the flows and phases from the individual zones or for updating the pertinent part of the reservoir model.
A problem associated with management of fluid flow at the outlet of a “Smart Well” comprising two or more branches or zones from which well effluents are produced is that this fluid flow stems from the commingled flux from two or more of the zones or branches of the well and does not provide information about the composition and flux of fluids produced via the individual zones or branches. Consequently, in conventional operation, the individual flux of fluids produced by the individual zones or branches cannot accurately be allocated to the zones or branches or be tracked or be controlled in real time or over a period of time. Further, due to the pressure and flow interactions between the individual zones or branches, it is difficult to control the pressures or the production at the branches and zones even with inflow control devices, particularly as the devices allow only a limited range of positions and transitions between positions. The inability to track the individual zone or branch productions or to control the zone or branch pressures, together with the variability and uncertainty of the reservoir and zone or branch production properties over time, leads immediately to difficulties in managing the extended reach wells to optimize the effluent production of the wells or the ultimate recovery of effluents from the reservoir or reservoirs which the extended reach well drains. As an example, over-production of fluids in one zone or branch of a well may result in under-production from other zones or even cross-flow from strong zones to weak zones, and reduce the ultimate total oil recovered in the well.
In the present state of the art, subsurface multiphase flow measurement devices are often too expensive, have too restricted an operating envelop and are too complex to install in individual well subsurface zones or branches to allow individual oil, water and gas components of the individual well subsurface zones or branches to be measured continuously and reli-ably in real time, particularly as the multiphase flow characteristics and properties change significantly over the life of the well.
SPE paper 102743 addresses the critical requirement to estimate downhole production from each zone by proposing computational algorithms based on formulae on thermodynamic, fluid mechanic laws or pre-computed correlations. Such approach based on rigorous physical and flow models requires many significant characterizations, measurements and parameters not practically or economically available over the production life of an extended reach well, in oil and gas production environment. Additionally, such application also requires manual ad hoc tuning adjustments from time to time to relate the resulting models to observed reality.
Applicant's International patent application PCT/EP2005/055680, filed on 1 Nov. 2005, “Method and system for determining the contributions of individual wells to the production of a cluster of wells” discloses a method and system named and hereafter referred to as “Production Universe Real Time Monitoring” (PU RTM). The PU RTM method and apparatus allows accurate real time estimation of the contributions of individual wells to the total commingled production of a cluster of crude oil, gas and/or other fluid production wells, based on real time well measurement data such as well pressures, in combination with well models derived from data from a shared well testing facility for the individual testing of wells, and dynamically reconciled regularly with the total commingled production data.
Applicant's International patent application PCT/EP2007/053345, filed on 5 Apr. 2007, “Method for determining the contributions of individual wells and/or well segments to the production of a cluster of wells” discloses a method and system named and hereafter referred to as “PU RTM DDPT”. The PU RTM DDPT, used in association with the method of PU RTM, allows the accurate real time estimation of the contributions of individual wells or well zones to the total commingled production of a cluster of crude oil, gas and/or other fluid production wells, based real time well data, in combination with well or zone models based on data derived solely from the metering of commingled production flows. The PU RTM DDPT method is specifically applicable and necessary for application of PU RTM data driven methods in oil and gas production facilities without a shared well testing facility for the individual testing of wells.
Applicant's International patent application PCT/EP2007/053348, filed on 5 Apr. 2007, “METHOD AND SYSTEM FOR OPTIMISING THE PRODUCTION OF A CLUSTER OF WELLS” discloses a method and system named and hereafter referred to as “PU RTO”. The PU RTO, used in association with the method of PU RTM, provides a method and system to optimise the day to day production of a cluster of wells on the basis of an estimation of the contributions of individual wells to the continuously measured commingled production of the cluster of wells, tailored to the particular constraints and requirements of the oil and gas production environment. However, limitations of the “PU RTO” approach as applied to the control of the subsurface zones of an extended reach well include:
a. Its main reference being continuously measured commingled production of the cluster of wells under optimization, whereas for well with subsurface zones, often the key requirement is to control the zonal pressures to achieve equal zonal annulus pressures, and total flow from the well is conversely not continuously measured;b. It assumes a common header pressure that characterizes the well interactions, whereas in extended reach wells, a different effluent flow topology and interaction pattern exists;c. The PU RTO assumes a low level of interaction between individual wells or zones, whereas in extended reach wells, the interaction components are significant and even backflow into weak zones is possible.d. The PU RTO assumes continuous values of the manipulated variables, whereas in the current state of the art, the multizone well zone ICD settings are restricted on a discrete set of values, and allow only limited transitions between positions, for example, only step by step incremental openings, and only closing to full close position.
It is therefore an object of the present invention to provide a method and system that supports the allocation and control of the individual zones of an extended reach well via appropriate position settings of the individual zone ICDs to optimise the day to day production of the well, addressing limitations in a, b, c, d above.